Viscous Oil Recovery by Polymer Injection; Impact of In-Situ Polymer Rheology on Water Front Stabilization

2018 ◽  
Author(s):  
Bartek Vik ◽  
Abduljelil Kedir ◽  
Vegard Kippe ◽  
Kristian Sandengen ◽  
Tormod Skauge ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Polymer Rheology ◽  
Polymer Injection ◽  
Viscous Oil ◽  
Water Front

Viscous Oil Recovery and In Situ Deasphalting in Fractured Reservoirs: Part 1. The Effect of Solvent Injection Rate

2018 ◽  
Vol 32 (1) ◽  
pp. 360-372 ◽  
Author(s):  
Chao-Yu Sie ◽  
Bradley Nguyen ◽  
Marco Verlaan ◽  
Orlando Castellanos-Diaz ◽  
Kelli Adiaheno ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Injection Rate ◽  
Solvent Injection ◽  
Effect Of Solvent ◽  
Viscous Oil

Design Researches in Making In-Situ Thermal Foam System as a New Enhanced Heavy Oil Recovery Method

2021 ◽  
Author(s):  
Vladimir Nikolaevich Kozhin ◽  
Andrey Valerevich Mikhailov ◽  
Konstantin Vasilievich Pchela ◽  
Ivan Ivanovich Kireev ◽  
Sergey Valerevich Demin ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Ionic Composition ◽  
Chemical Effect ◽  
Recovery Method ◽  
Injection Process ◽  
Viscous Oil ◽  
Reservoir Conditions ◽  
Displacement Factor ◽  
Water Gas

Abstract The paper presents the results of lab and filtration studies aimed at improving the procedure of thermal/gas/chemical effect (TGCE) with the generation of thermogenic system in reservoir conditions, proposed as an alternative to the methods of increasing oil recovery, such as water-gas effect procedure and foam injection process. The objects of research were thermal/gas generating compositions at the basis of sodium salts of sulfamic and nitric acids. Moreover, the influence of the ionic composition of the aqueous solution and temperature on the surface properties of the attracted solutions of surfactants (surfactants) was also evaluated. Filtration tests have shown that the use of a thermal/gas generating composition leads to additional displacement of high-viscous oil. The introduction of surfactants in the thermal/gas generating composition promotes foaming in the porous medium of the reservoir model and prevents gas breakthrough that leads to an increase in the oil displacement factor up to 24 %.

Combined In Situ CO2 Generation and Chemical Flooding for Viscous Oil Recovery

2011 ◽  
Author(s):  
B.J. Ben Shiau ◽  
Tzu-Ping Hsu ◽  
Sang-Ho Bang ◽  
Bruce L. Roberts ◽  
Jeffrey H. Harwell
Keyword(s):  
Oil Recovery ◽  
Chemical Flooding ◽  
Viscous Oil

Experimental Investigation of In-Situ Emulsion Formation To Improve Viscous-Oil Recovery in Steam-Injection Process Assisted by Viscosity Reducer

SPE Journal ◽  
2016 ◽  
Vol 22 (01) ◽  
pp. 130-137 ◽  
Author(s):  
Chuan Lu ◽  
Huiqing Liu ◽  
Wei Zhao ◽  
Keqin Lu ◽  
Yongge Liu ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Steam Injection ◽  
Viscosity Reduction ◽  
Injection Process ◽  
Viscous Oil ◽  
Viscosity Reducer ◽  
High Temperature Steam

Summary In this study, the effects of viscosity-reducer (VR) concentration, salinity, water/oil ratio (WOR), and temperature on the performance of emulsions are examined on the basis of the selected VR. Different VR-injection scenarios, including single-VR injection and coinjection of steam and VR, are conducted after steamflooding by use of single-sandpack models. The results show that high VR concentration, high WOR, and low salinity are beneficial to form stable oil/water emulsions. The oil recoveries of steamflooding for bitumen and heavy oil are approximately 31 and 52%, respectively. The subsequent VR flooding gives an incremental oil recovery of 5.2 and 6.4% for bitumen and heavy oil, respectively. Flooding by steam/VR induces an additional oil recovery of 8.4–11.0% for bitumen and 12.1% for heavy oil. High-temperature steam favors the peeling off of oil and improving its fluidity, as well as the in-situ emulsions. VR solution is beneficial for the oil dispersion and further viscosity reduction. The coinjection of high-temperature steam and VR is much more effective for additional oil production in viscous-oil reservoirs.

scholarly journals Discerning In-Situ Performance of an Enhanced-Oil-Recovery Agent in the Midst of Geological Uncertainty: II. Fluvial-Deposit Reservoir

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1076-1091
Author(s):  
S. A. Fatemi ◽  
J.-D.. -D. Jansen ◽  
W. R. Rossen
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Geological Uncertainty ◽  
Polymer Injection ◽  
Fluvial Deposit ◽  
Water Breakthrough ◽  
Production Wells ◽  
Reservoir Description

Summary An enhanced-oil-recovery (EOR) pilot test has multiple goals, among them to be profitable (if possible), demonstrate oil recovery, verify the properties of the EOR agent in situ, and provide the information needed for scaleup to an economical process. Given the complexity of EOR processes and the inherent uncertainty in the reservoir description, it is a challenge to discern the properties of the EOR agent in situ in the midst of geological uncertainty. We propose a numerical case study to illustrate this challenge: a polymer EOR process designed for a 3D fluvial-deposit water/oil reservoir. The polymer is designed to have a viscosity of 20 cp in situ. We start with 100 realizations of the 3D reservoir to reflect the range of possible geological structures honoring the statistics of the initial geological uncertainties. For a population of reservoirs representing reduced geological uncertainty after 5 years of waterflooding, we select three groups of 10 realizations out of the initial 100, with similar water-breakthrough dates at the four production wells. We then simulate 5 years of polymer injection. We allow that the polymer process might fail in situ and viscosity could be 30% of that intended. We test whether the signals of this difference at injection and production wells would be statistically significant in the midst of geological uncertainty. Specifically, we compare the deviation caused by loss of polymer viscosity with the scatter caused by the geological uncertainty using a 95% confidence interval. Among the signals considered, polymer-breakthrough time, minimum oil cut, and rate of rise in injection pressure with polymer injection provide the most-reliable indications of whether a polymer viscosity was maintained in situ.

New Insights into Geochemical Modeling of Hybrid Low Salinity/Engineered Water and Polymer Injections in Carbonates

2021 ◽  
Author(s):  
Emad W. Al-Shalabi ◽  
Waleed Alameri
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Polymer Rheology ◽  
Hybrid Polymer ◽  
Sweep Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Harsh Conditions

Abstract For decades, polymer flooding proved to be one of the most effective enhanced oil recovery (EOR) methods. In addition, low salinity/engineered water injection (LSWI/EWI) has been gaining momentum over the last few years. Both techniques seem to be cheaper than other EOR methods. This resulted in an increased interest among operators in these techniques. Moreover, low-salinity water is usually less viscous compared to formation fluids, which warrants a lower volumetric sweep efficiency, especially at high temperatures and in highly heterogeneous formations. The reduction in macroscopic sweep efficiency impairs the improvement in recovery efficiency by low-salinity water. In addition, experimental studies showed that polymer viscosity is considerably improved in less saline water. In this study, hybrid polymer and LSWI/EWI flooding performance is numerically evaluated in carbonate formations under conditions of mixed-to-oil wettability, high temperature, high salinity, and low permeability. A numerical 1D model was constructed using a commercial compositional simulator. The model captures the polymer rheology of a newly developed and commercially available synthetic polymer. Also, the effect of LSWI/EWI on polymer rheology and performance was studied. Oil recovery, pressure drop, and in-situ saturation data were history matched for seawater, polymer, and low salinity water injection cycles. Furthermore, the matched experimental data were utilized to examine the combined polymer and low salinity water effect on the improvement in microscopic displacement efficiency of linear models under reservoir flow conditions. The simulation results showed that hybrid polymer and LSWI/EWI is a viable EOR method for carbonate reservoirs under harsh conditions. Moreover, this work provides new insights into the hybrid application of LSWI/EWI and polymer flooding in carbonates under harsh conditions, the impact of low-salinity water on in-situ polymer rheology, and it promotes further field-scale applications of hybrid polymer-LSWI/EWI to improve volumetric sweep efficiency and overall recovery efficiency.

Experimental Investigation of Hybrid Techniques for Enhancing Alaska North Slope Viscous Oil Recovery

2021 ◽  
Author(s):  
Yaoze Cheng ◽  
Yin Zhang ◽  
Abhijit Dandekar
Keyword(s):  
Oil Recovery ◽  
Pressure Gauge ◽  
Measurement Range ◽  
Differential Pressure ◽  
Viscosity Reduction ◽  
North Slope ◽  
Oil Viscosity ◽  
Polymer Injection ◽  
Hybrid Techniques ◽  
Viscous Oil

Abstract Alaska North Slope (ANS) contains vast viscous oil resources that have not been developed effectively due to the lack of efficient Enhanced Oil Recovery (EOR) techniques. This study investigates the EOR performance of three new hybrid EOR techniques: HSW-LSW-LSP flooding, solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding. Additionally, pressure-volume-temperature (PVT) tests have been conducted to investigate the oil swelling and viscosity reduction effects of the proposed solvent. It has been found that the oil recovery of HSW flooding was 43.42%, while the tested HSW-LSW-LSP flooding, solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding could improve the oil recovery to 74.17%, 79.73%, and 85.87%, respectively. All three proposed hybrid EOR techniques can significantly enhance the viscous oil recovery since they were all designed to both improve the microscopic and macroscopic sweep efficiencies. In particular, the PVT test results confirmed that the proposed solvent in this study could effectively swell the viscous oil over 30% and significantly reduce the viscous oil viscosity by about 97%. However, the initially designed solvent-alternating-LSP flooding displacement experiment had to be terminated after the first slug of polymer injection due to the extremely high differential pressure, which was over the measurement range of the pressure gauge. Thus, the actually tested displacement process in this study was solvent-LSP flooding. The extremely high differential pressure was found to result from the polymer deposit and blockage at the outlet. Although the proposed solvent-alternating-LSP flooding may produce the highest oil recovery, it cannot be applied in the field until the issue of polymer precipitation is understood and solved. The study has practical guidance to the selection of proper EOR techniques to enhance viscous oil recovery on ANS.

Viscous oil recovery and in-situ deasphalting in fractured reservoirs – Part 2: Effect of solvent type and temperature

Fuel ◽  
2019 ◽  
Vol 247 ◽  
pp. 294-301 ◽  
Author(s):  
Chao-Yu Sie ◽  
Bradley Nguyen ◽  
Orlando Castellanos Diaz ◽  
Marco Verlaan ◽  
Quoc P. Nguyen
Keyword(s):  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Effect Of Solvent ◽  
Viscous Oil ◽  
Solvent Type

scholarly journals Polymer Injectivity Test Design Using Numerical Simulation

Polymers ◽  
2020 ◽  
Vol 12 (4) ◽  
pp. 801
Author(s):  
Mohamed Adel Alzaabi ◽  
Jørgen Gausdal Jacobsen ◽  
Shehadeh Masalmeh ◽  
Ali Al Sumaiti ◽  
Øystein Pettersen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Soluble ◽  
Polymer Rheology ◽  
Water Soluble Polymers ◽  
Shear Rates ◽  
Soluble Polymers ◽  
High Shear Rates ◽  
Water Viscosity ◽  
Source Of Information

Polymer flooding is an enhanced oil recovery (EOR) process, which has received increasing interest in the industry. In this process, water-soluble polymers are used to increase injected water viscosity in order to improve mobility ratio and hence improve reservoir sweep. Polymer solutions are non-Newtonian fluids, i.e., their viscosities are shear dependent. Polymers may exhibit an increase in viscosity at high shear rates in porous media, which can cause injectivity loss. In contrast, at low shear rates they may observe viscosity loss and hence enhance the injectivity. Therefore, due to the complex non-Newtonian rheology of polymers, it is necessary to optimize the design of polymer injectivity tests in order to improve our understanding of the rheology behavior and enhance the design of polymer flood projects. This study has been addressing what information that can be gained from polymer injectivity tests, and how to design the test for maximizing information. The main source of information in the field is from the injection bottom-hole pressure (BHP). Simulation studies have analyzed the response of different non-Newtonian rheology on BHP with variations of rate and time. The results have shown that BHP from injectivity tests can be used to detect in-situ polymer rheology.

Simulation of Polymer Injection Under Fracturing Conditions—An Injectivity Pilot in the Matzen Field, Austria

2015 ◽  
Vol 18 (02) ◽  
pp. 236-249 ◽  
Author(s):  
Markus Zechner ◽  
Torsten Clemens ◽  
Ajay Suri ◽  
Mukul M. Sharma
Keyword(s):  
Polymer Solution ◽  
Field Test ◽  
Oil Recovery ◽  
Polymer Solutions ◽  
Oil Production ◽  
Polymer Rheology ◽  
Oil Viscosity ◽  
Polymer Injection ◽  
Stress Changes ◽  
The Impact

Summary Polymer flooding leads to enhanced oil recovery by accelerating oil production and improving sweep efficiency. However, because of the higher viscosity, the injectivity of polymer solutions is of some concern and is important to understand to predict incremental oil recoveries. Achieving high polymer-injection rates is required to increase oil-production rates. In the field test performed in the Matzen field (Austria), polyacrylamide polymers were injected for the past 2 years. Coreflood experiments with these polymers showed a significant increase in apparent viscosity because of the viscoelastic properties of the polymer solutions. Also, severe degradation of the polymer solution at high flow velocities was detected. In addition to coreflood experiments, flow experiments through fractures were performed. In these experiments, shear thinning and limited degradation of the polymer solution were observed and quantified. Detailed polymer-injection simulations were conducted that included complex polymer rheology in the fractures and the matrix. The reservoir stress changes and their effects on the fractures were also taken into account as a result of cold-polymer injection. The results of the simulations matched the field data both for waterfloods and polymer-test floods. The simulations revealed two distinct phases during the injection of the polyacrylamide-polymer solution: Injection under matrix conditions in an early phase resulting in severe degradation of the polymers Injection under fracturing conditions after the formation parting pressure is reached, leading to limited degradation of the polymers The calibrated model was used to investigate the impact of polymer rheology and particle plugging on injectivity and fracture growth. The results of the field test and the simulations indicate that screening of fields for polyacrylamide-polymer projects needs to include geomechanical properties of the reservoir sand and cap/base rock in addition to the conventional parameters used in screening such as oil viscosity, water salinity, reservoir temperature, and reservoir permeability.

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